Venezuela has the world’s largest proven oil reserves and is one of the founding members of OPEC. Despite this, their 2.5m bpd of oil production accounts for only 3% of global output. Venezuelan oil production declined over the last decade owing to complex geology and a difficult investment climate. However, several large IOC-operated gas fields offshore Venezuela could now offer some positivity.

The Hydrocarbon El Dorado

Venezuela’s 300bn bbl of oil reserves account for 18% of current global reserves. But 220bn bbls of these reserves are onshore in the Faja, or Orinoco heavy oil belt, which has produced around 1.3m bpd in recent years. Venezuelan heavy oil grades are a key part of world oil supply: many US refineries were designed to take its heavy grades of oil together with lighter Arab crudes, meaning the country is also important for the tanker market. But production from the Faja is expensive and technically challenging, and heavy crudes sell at a discount.

Making Heavy Work Of It

After the election of Hugo Chávez in 1999, Venezuela’s oil industry came under strain as social policies were funded by oil revenues, and reinvestment declined. After the 2003 general strike, 19,000 PDVSA employees were fired and replaced with government loyalists. Furthermore, in 2007, the government looked to capitalize on the high oil price environment by nationalizing international oil companies’ (IOCs’) assets.

Offshore production was always the minor fraction of Venezuela’s output (23%). However, lack of investment in maintenance hit it hard. This was particularly true of the very shallow water production in Lake Maracaibo, which has seen drilling for more than a century. Issues of pipeline leakage and even oil piracy on the lake helped production there decline. In total, output from the Maracaibo-Falcon basin (not exclusively offshore) fell 35% between 2008 and 2015. In total, offshore production is estimated to have dropped by about 38% to 0.57m bpd.

A Brighter And Lighter Future

The current political and fiscal situation in Venezuela offers little suggestion that it will be easy to arrest decline. However, a more permissive attitude to foreign investment may help. In October, agreements were signed to allow Chinese and Bulgarian investment to fund repairs offshore Lake Maracaibo. Perhaps more significant is the promise of gas, where greater IOC participation is permitted.

Trinidad, Venezuela’s very close neighbour, tripled their offshore production from 1998-2005. Venezuela has begun to make moves in the same direction, firstly via the Cardon IV project. The first field here, Perla, started up in 2015 run by an Eni-Repsol joint venture. As the graph shows, this has already had a small, but visible effect on Venezuelan gas output. Perla has reserves of 2.85bn boe and by Phase 3 is set to be producing 1.2 bcfd. This is likely to be added to from 2019 by up to 1 bcfd of output from the long-delayed Mariscal Sucre fields.

So, Venezuela has vast reserves but production has been falling. The political situation, combined with low oil prices, is likely to hinder any rapid turnaround in oil output. However, although progress has been slow, IOC involvement has at least provided some positive impetus for gas production offshore Venezuela.

To much fanfare and accompanied by voluminous industry coverage, Mexico recently concluded Round 1.4, the country’s first ever deepwater licensing round. However, Mexico’s shallow waters may yet have a future too: Bay of Campeche reserves remain considerable and indeed, the country’s third shallow water bid round is ongoing. It is therefore worth reviewing the current state of shallow water E&P in Mexico.

Veering Off Course

Mexican offshore oil is currently produced entirely from shallow water fields, as has always been the case. The key sources of Mexican offshore oil have been several large field complexes such as Cantarell and Ku-Maloob-Zaap. As these fields and others came online, the country’s offshore oil output grew with a robust CAGR of 6.6% from 1980 to 2004, reaching a peak of 2.83m bpd in 2004. As the graph implies, four complexes accounted for 93% of this production. Decline set in thereafter at ageing fields (production at Cantarell began at the Akal field in 1979). Pemex – the sole operator of Mexican offshore fields prior to 2014 – tried to halt production decline, but with little success, given budget and technical constraints. Thus by 2013, offshore oil production at the four key field complexes had fallen to 1.31m bpd, accounting for 69% of Mexico’s offshore oil production of 1.90m bpd.

Getting Back On Track

This situation prompted President Peña Nieto’s government to initiate energy sector reforms in 2013, opening up the country’s upstream sector to foreign companies for the first time since 1938. Pemex was granted 83% of Mexican 2P reserves in “Round Zero” in 2014. The first shallow water round, Round 1.1, followed in December 2014. Only two of 14 blocks were awarded though, reportedly due to unfavourable fiscal terms inhibiting bidding by oil companies. The authorities then improved terms before launching Round 1.2 (shallow water), Round 1.3 (onshore) and Round 1.4 in 2015. Round 1.2 was better received than 1.1: as per the inset, 60% of blocks were awarded (75% of the km2 area on offer). One of the round’s victors, Eni, has already been granted permission to drill four appraisal wells on Block 1.

Turning Things Around?

In light of these positives, there are high hopes for Round 2.1, a shallow water round launched in July 2016. Indeed, 10 out of the 15 Round 2.1 blocks are in the prolific Sureste Basin, home to the Cantarell complex. Eight of these ten areas are unexplored, so there is sizeable upside potential, and have been mapped with 3D seismic, so operators could begin drilling promptly. Moreover, the surface area of the blocks in Round 2.1 are twice that of Round 1.1. It should also be noted that according to a 2016 IEA study, Mexico’s shallow waters still account for 29% of the country’s remaining technically recoverable oil resources. Finally, with rates for a high spec jack-up in the GoM assessed at about $85-90,000/day in January 2017, down 45% on three years ago, some oil companies might be tempted to make a move on a round that could offer a relatively low cost means to grow oil reserves and production.

So arguably, Mexican shallow water E&P is on the road again. There are potential hazards of course, such as oil price volatility or Mexico’s relationship with the US. But it is not implausible to think that Mexican shallow water oil production might speed up again in the coming years.

The expansion of European settlement in North America – the pushing westwards of the frontier – has come to be seen as a defining part of American culture, spawning a whole genre of films and books set in the historical “Wild West”. That same pioneering spirit seems to be alive still today, at least in the US Gulf of Mexico (GoM), where 49 ultra-deepwater field discoveries have been made in the last decade.

Once Upon A Time In The Gulf

Offshore E&P in the US GoM began in the 1930s, picking up pace in the 1950s. By the end of 1975, a total of 444 shallow water fields had been discovered in the area and 256 of these had been brought into production. Gas fields predominated, accounting for 75% of discoveries and 31% of start-ups. Early E&P in the area made extensive use of jack-up drilling rigs and lift-boats. Fixed platforms were the favoured development method, with 86% of the 256 start-ups using fixed platforms. Thus were the first pioneering steps taken in exploiting the US GoM.

For A Few Dollars More

However, compelled by the need to find new reserves, oil companies active in the US GoM began pushing outwards, into deeper waters: the first deepwater discovery in the area was made in 1976. The frontier has now moved quite a way onwards since those early days. The average distance to shore of the 129 offshore discoveries in the area since start 2007 is 145km, while 72% (93) of these fields are in water depths of 500m or greater. The focus has also shifted from gas to oil: 58% of the 129 finds were oil fields, including 81% of the 93 deepwater finds. The US GoM has been dubbed one corner of the “Golden Triangle” of deepwater E&P and (supported by high oil prices until 2015) it has accounted for 16% and 19% of deepwater and ultra-deepwater finds globally since 2007. As shown by the graph, this was in spite of a slowdown in the wake of Deepwater Horizon. Floater utilisation dipped to 80% in 2011 but recovered, and a peak of 54 active floaters in the area was reached in January 2015 (26% of the active fleet).

Manifest Destiny?

So US GoM exploration was a major beneficiary of a high oil price. But how might it fare in a potential “lower for longer” price scenario? The outlook for jack-ups is bleak, with utilisation in the area standing at 24% as of December 2016. Simply put, the shallow water GoM is gas prone, and gas fields in the area are generally not competitive with onshore shale gas. At the US GoM (ultra-)deepwater frontier though, things do not look quite as bad as might be expected. On the one hand, over the last two years, floater utilisation has gradually fallen to 70%, as owners have struggled with rig oversupply, and dayrates are severely pressurised. On the other hand, there have been large finds made since 2014, such as Anchor and Power Nap, and wells are underway or planned for potentially major prospects such as Dawn Marie, Warrior, Castle Valley, Hershey, Hendrix, Sphinx and Dover. Many oil companies see the US GoM as a core area, and are prepared to invest to bolster oil reserves, even via drilling of, for example, costly HPHT reservoirs in the Lower Tertiary Wilcox formation.

As in the Wild West, at times things can be tough at offshore frontiers. Rig owners (and others) are experiencing this in the US GoM. But with some oil companies taking a long-term view, the pioneering spirit may not have been snuffed out yet.

Vietnam has the third largest proven oil reserves in the Asia Pacific region – but much of its existing offshore production is from declining shallow water fields. So the country’s first deepwater discovery, made in October, is a potentially exciting development. Could deepwater E&P activity in Vietnam be set to take off, or will weak oil prices and disputes over territorial waters prove problematic?

Shallow Beginnings

Most of Vietnam’s 0.28m bpd of offshore oil and 0.99bn cfd of offshore gas production is derived from fields in the Nam Con Son and Cuu Long basins, all of which are in less than 200m of water. The Cuu Long basin is perhaps the most successful area off Vietnam as it is home to many large fields, including Bach Ho, Su Tu Vang and Rang Dong. The dominance of shallow fields has skewed development towards fixed platforms. 88% of all active Vietnamese fields are exploited as such. Of these fields, the Bach Ho field accounts for 34 cor 37% of the total found on active fields.

Operators in Vietnam mainly consist of local and regional NOCs as well as IOCs (most commonly via joint operating companies in partnership with Petrovietnam). While significant market reforms have increased foreign investment in Vietnam’s offshore sector, further improvements to its transaction and tax systems could quicken the pace of foreign participation in the future.

Wading Into Deeper Waters

No significant shallow discoveries have been made recently, meaning that there is little to offset Vietnam’s depleting shallow water reserves. This highlights the need to break into deepwater frontiers, which could hold substantial levels of undiscovered hydrocarbons. The VGP-131-TB well, Vietnam’s first discovery in water depths >500m, was drilled in October 2015 by the Vietgazprom JOC, at depths of 1,600m in the Saigon basin. The ultra-deep find could provide momentum for Vietnam’s push into deepwater exploration. However, unlike China, which is able to independently bring deepwater fields like the Lingshui 17-2 online, Vietnam could still need to rely on foreign cooperation to jointly develop such finds in the short term.

Shaky Prospects

Vietnam’s hydrocarbon resources mainly lie in the South China Sea, with the most recent discovery at the southern end. The sea is an area of multiple disputed territorial claims by many countries, including China. This could impede any deep developments, if international partners were to view overlapping sovereignty claims to be an excessive business risk. Perhaps more importantly though, the post-downturn attitude of IOCs is one of cost-consciousness given lacklustre economic conditions. This could skew near-term interest towards safer EOR projects instead of unproven deeper water development in the South China Sea.

Since Vietnam’s historical track record is in shallow waters, even if further deepwater discoveries are forthcoming, then the chance of rapid deepwater developments in the South China Sea is probably going to take time. It is likely to need outside expertise, and the current energy markets may well not be conducive to this. That said, the discovery of Vietnam’s first deepwater field marks a new chapter in the country’s oil and gas story.

Russia is forecast to account for 13% of world crude oil production and 18% of world natural gas production in 2014. While its prodigious Siberian flows tend to receive most of the credit for this feat, fields located off the country’s 16 million km of coastline are nonetheless projected to produce 390,000 bpd oil and 2.64 bcfd gas in 2014. So where exactly is Russian offshore production to be found? And what is the outlook?

Mastering the Arctic

As the Graph of the Month shows, offshore oil and gas production in Baltic & Arctic Russia stagnated after the break-up of the USSR, declining to 0.03m boepd in 2013, when it accounted for 4% of Russian offshore production. This trend was thrown into reverse when the Prirazlomnoye field came onstream in December 2013. Located 23km from shore in the Pechora Sea, the field is exploited via a ice-class platform and production is scheduled to reach 120,000 bpd by 2019. New technologies and robust oil prices are thus unlocking reserves hitherto stranded, and by 2023 Arctic oil and gas is forecast to constitute 11% of Russia’s offshore production.

Caspian and Crimean Conquests

Russia’s southern offshore fields, mainly in the Caspian, accounted for 9% of Russian offshore production in 2013. In the Caspian, as in the Arctic, harsh conditions have limited field development and disincentivised efforts to halt production decline. However, as in the Arctic, decline is now forecast to be arrested. Lukoil, for example, are planning substantial investment over the next four years at fields like Khvalynskoye and Yuri S. Kuvykin, where ice-class jack-up production units are likely to make development feasible. By 2023, the area is forecast to account for 24% of Russian offshore oil and gas production (excluding gas produced by fields off the Crimea, over which Russia now has de facto control, and which produced 410m cfd in 2013).

Expanding Eastwards

The Russian Far East is a relatively new area of offshore E&P. The Sakhalin-2 project started up in 1996 but offshore activity is still geographically limited, even if production volumes, at 0.78m boepd, are significant. The area accounted for 88% of Russian offshore production in 2013. Moreover, the Far East is Russia’s window on the developing economies of the Asia Pacific region, so companies are seeking to increase activity there, particularly with regards to LNG. In October 2013, the first Sakhalin-3 field, Kirinskoye, a subsea-to-shore development, began ramping up to 580m cfd. Further such field developments are planned out to 2023, when the area is projected to produce 0.95m boepd, its share falling to 65% despite new Capex due to faster Arctic and Caspian growth.

Thus production is forecast to grow in each of Russia’s offshore areas, driven largely by investment in high-spec jack-up, fixed platform and subsea field solutions. Total offshore oil production is projected to grow with a CAGR of 8.9% from 2014 to reach 890,000 bpd in 2023, and gas production likewise at 2.5% to reach 3.36 bcfd. Offshore would then account for 6.7% of the country’s oil and gas production, a far cry from the 2% nadir of post-Soviet decay.

Since the country’s oil reserves were nationalised by Lázaro Cárdenas in 1938, the state ownership of Mexico’s oil production has been an issue of totemic pride for Mexicans. For years, the bounty provided by the Cantarell project minimised the need to think about other options. But as the decline of ageing Bay of Campeche fields accelerates, increasing investment has been needed by Pemex both to shore up existing fields and also to appraise future areas of production.

Exploring Investment Expansion

The Graph of the Month shows the extent of the growth in Pemex’s Exploration and Production budget, as greater focus has come on developing new areas of oil production, some involving deeper waters or more complex development types than the fixed platforms found on Cantarell or Ku-Maloob-Zaap. Pemex’s E&P budget in 2013 was around 74% greater than five years earlier, and its projection for total expenditure is for further growth in its CAPEX budget through to 2018 at a rate of 3.8% per annum. Although this forecast is at an aggregate level, including all business units, the line on the graph shows the level of E&P spending that this implies given the share which the latter has been in recent history.

A Landmark Policy Change

On December 23rd, in the face of not-inconsiderable political opposition, the Mexican president signed a constitutional reform which, will end the 75-year old state monopoly on Mexican production, and allow private investment in Mexican developments. This could add to Pemex’s already substantial $149bn five-year investment plan.

Supporting Structures

This is, of course, all positive news to owners of offshore structures, raising the potential for greater future demand for structures off Mexico. Mexico is already beginning to generate demand for increasing numbers of rigs and OSVs. A number of Mexico-based companies have attracted investment from US and Asian sources of finance looking to gain exposure to the Mexican market (notably the expected need for additional high-specification jack-ups: at least 18% of the current orderbook is for deployment there).

As well as continued work to shore up output on the major fields, plans for new fields are underway. These include the FPSO development on the Ayatsil heavy oil field (targeting 2016 start-up) and Lakach, Pemex’s first deepwater project (2015). This field has been followed by several other finds in the Catemaco fold belt off Veracruz, results of the recent step-up in exploration by Pemex. Hub development may be possible, although falling American gas prices could be an issue. Looking further to the future, potential further deepwater activity could include a SPAR in the Perdido fold belt near US waters.

So, the future for investment offshore Mexico looks relatively bright, with optimistic projections for the levels of state investment. The lack of local experience in deep or more complex fields could be an issue, but as private investment and more third-party offshore contractors get involved, these challenges may be solved. All together, this makes Mexico an attractive prospect, as the drive towards new production stimulates additional demand for offshore units.